Eni and Vår Energi to acquire Neptune, a leading independent exploration and production company with low emission, gas-oriented operations in Western Europe, North Africa, Indonesia and Australia

Eni S.p.A. (“Eni”) is pleased to announce that along with Vår Energi ASA (“Vår”) it has reached an agreement to acquire Neptune Energy Group Limited (“Neptune”).

Neptune is a leading independent exploration and production company with a world-class portfolio of gas-oriented assets and operations in Western Europe, North Africa, Indonesia and Australia. The portfolio is competitive in terms of cost and low in operational emissions. Neptune was founded in 2015 by Sam Laidlaw and is currently owned by China Investment Corporation, funds advised by Carlyle Group and CVC Capital Partners, and certain management owners.

Eni will acquire assets comprising Neptune’s entire portfolio other than its operations in Germany and Norway (the “Neptune Global Business”) (the ‘’Eni transaction’’). The German operations will be carved out prior to the Eni transaction and the Norwegian operations (the Neptune Norway Business’’), will be acquired by Vår directly from Neptune under a separate share purchase agreement (the “Vår transaction”) (the Eni transaction and the Var transaction together comprising the “transaction”).

The Vår transaction will close immediately prior to the Eni transaction with the proceeds from the Norway sale remaining with the Neptune Global Business purchased by Eni. Vår is a company listed on the Oslo Stock Exchange and is 63% owned by Eni.

Under the agreed terms, the Neptune Global Business will have an Enterprise Value of c.$2.6bn, while the Neptune Norway Business will have an Enterprise Value of c.$2.3bn. As of 31 December 2022, net debt of the Neptune Global Business, pro forma for the sale of the Neptune Norway Business, was c.$0.5bn. The final net consideration for both transactions will be subject to customary closing adjustments and will be paid in cash at completion. The Eni transaction will be funded through available liquidity.

The transaction represents an exceptional fit for Eni. It complements Eni’s key areas of geographic focus and supports its objective of increasing the share of natural gas production to 60%, and reaching net zero emissions (Scope 1+2) from the Upstream business by 2030. The transaction aligns with Eni’s strategy of providing affordable, secure and low carbon energy to society, for which natural gas remains an important source. The transaction is also consistent with Eni’s operating and financial framework, as well as the targets set out in Eni’s 2023-2026 Plan, delivering earnings and cashflow accretion, additional shareholder value and remuneration upside.

Specifically, the transaction has the following benefits:

• As of 31 December 2022, reported 2P reserves of c.484 million boe of which c.386 million boe are net to Eni’s portfolio[1], and of which c. 80% is natural gas. The transaction equates to a 2P acquisition cost of $10.1/boe. In addition, there is significant additional contingent resource upside.
• For the year ended 31 December 2022, Neptune reported revenues of c.$1.22bn and EBITDAX of c.$0.95bn for the Neptune Global Business.
• The transaction will add around 130 kboed[2] to the Eni and Var portfolios. From this, Eni estimates the transaction will add more than 100 kboed of low emission production1 over 2024-2026, of which more than 70% will be natural gas (compared to 53% for Eni in 2022), with almost all of that amount capable of supplying OECD markets via pipeline or LNG.
• Eni expects to generate G&A and industrial synergies to a value of over $0.5bn, with additional cost synergies, exploration and development including more CCS, financial and midstream value upside potential.
• The transaction is expected to be immediately accretive to earnings and CFFO per share, as well as free cashflow positive. It is also consistent with the 2023-2026 Plan presented in February 2023, in particular the guidance of:
• €1bn net positive contribution from portfolio activities over the period
• €37bn of organic capex over the period
• Leverage within a 10% to 20% range
• Achieving 2023-26 production CAGR of 3-4% predominantly through organic investment plus the net impact of inorganic high-grading activities. 

This will see Eni integrate new assets that deliver additional value, while divesting others as it restructures and simplifies its portfolio.

Commenting on the transaction, Eni’s CEO, Claudio Descalzi, said ‘’This transaction delivers to Eni a high-quality and low carbon intensity portfolio with exceptional strategic and operational complementarity. Eni sees gas as a critical bridge energy source in the global energy transition and is focused on increasing the share of its natural gas production to 60% by 2030. Neptune will contribute predominantly gas resources to Eni’s portfolio. Moreover, the geographic and operational overlap is striking, adding scale to Eni’s majority-owned Vår Energi; bringing more gas production and CCUS opportunities to the remaining North Sea footprint; building on Eni’s leading position in Algeria – a key supplier to European gas markets; and deepening Eni’s presence in offshore Indonesia, supplying the Bontang LNG plant and domestic markets. We also expect the added supply to provide further optimisation opportunities for Eni’s GGP operations. Indeed, we see the transaction adding around 4 Bcm of gas supply for European consumers. A critical element of the transaction is also the low-cost supply and accretive cashflow it provides to Eni. It therefore supports our commitment to an attractive and resilient dividend and adds to the potential for share buybacks that make up the balance of the 25-30% of CFFO we have committed to distribute. The nature and challenges of the energy transition require a focused response and in particular this transaction highlights two important aspects of Eni’s financial strategy – the flexibility and optionality that our strong liquidity and low balance sheet leverage offer; and our innovative satellite model which helps to align and access dedicated capital”.

Overview of portfolio acquired

The transaction has strong complementarity with Eni’s existing operations and strategy:Neptune Global Business

• UK: In 2022 Neptune produced 15kboed, of which most relates to gas production from its operated and long-life Cygnus field, the UK’s largest single gas producer. Additionally, Neptune is currently developing the operated Seagull field which is due to come onstream in 2H 2023. In 2022, Eni produced 44kboed in the UK mainly from the non-operated Elgin Franklin and J-Block.
• Netherlands: In 2022 Neptune produced 18kboed, of which most relates to gas production. Neptune is the largest producer in the Dutch North Sea and operates several key offshore hubs which provide opportunity to efficiently add new reserves and production through infill drill and tiebacks. Eni does not have E&P operations in the Netherlands but the additional source of gas supply will improve the geographical and pipe versus LNG diversification of our well established and successful midstream gas GGP operations.
• Algeria (and Egypt): Neptune operates the Touat field in Algeria. Touat production is currently suspended but will restart once upgrades to the processing facilities are complete with plateau production at 100% of over 400Mscfd (~70kboed). Neptune production from the Western Desert in Egypt in 2022 was 3kboed. In 2022, Eni produced 95kboed in Algeria and 346kboed in Egypt. In the context of the war in Ukraine, Algeria has become a key supplier of gas to Europe. Eni, as the leading IOC in the country, has taken a leading role in this initiative and expects 2023 production will average more than 120kboed in the country.
• Indonesia: Neptune production in Indonesia of over 20kboed came from the Eni operated Jangkrik and Merakes fields which supply gas to the Bontang LNG facility and domestic customers. Eni production in 2022 was 62kboed.
• Australia: Neptune maintains an interest in the Petrel project in the Bonaparte Basin, offshore Australia. Though development options for Petrel are currently being assessed, there could be optionality to leverage existing infrastructure including the Eni (100%) Blacktip field which produces and processes gas offshore for delivery to shore.
• Neptune Norway Business: In 2022 the Neptune Norway Business accounted for 58kboed of low cost and low emission production, of which 57% was gas or LNG. Neptune’s principal assets in the country are Snøhvit, Njord, Gudrun, Fenja, Duva, Gjøa and Fram of which Fenja, Duva and Gjøa are operated. In 2022, Neptune completed development activities on Njord and Fenja, with both expected to contribute to production growth this year. Future growth is expected to be driven by a number of short-cycle tie-back opportunities to existing infrastructure. In 2022, Vår produced 220kboed. The combination in Norway brings together two high performing organisations with extensive experience in exploration and project development and significant opportunities to create additional value while reducing emissions.
• Low carbon: The Neptune portfolio production in 2022 was comprised of 77% gas[3]. The Scope 1 & 2 carbon intensity of operated production in 2022 was 5.9 kgCO2eq/boe3
• CCUS opportunities: Neptune is advancing CCS projects in Norway, the Netherlands and the UK with FEED at the L10 project in the Netherlands expected to commence this year. Eni regards CCS as a key lever in its decarbonization strategy targeting a gross capacity of 30Mtpa by 2030. Ravenna CCS is expected to start up in 2024 and HyNet in the UK is advancing as one of two ‘Track 1’ projects. Eni is also working on the Bacton CCS project in the UK, Bahr Essalam in Libya and other projects in Egypt, Australia and the UAE.

OMV Petrom and Romgaz announce the decision to develop Neptun Deep, the largest natural gas project in the Romanian Black Sea

OMV Petrom, the largest integrated energy company in South-Eastern Europe, and Romgaz, the largest producer and main supplier of natural gas in Romania, approved the development plan for the Domino and Pelican South commercial natural gas fields in the Neptun Deep block. This will be submitted to the National Agency for Mineral Resources for endorsement. OMV Petrom is the operator, with each company having a 50% interest in the project.

OMV Petrom and Romgaz will invest up to EUR 4 bn for the development phase of the project, which will enable ~100 bcm of natural gas to be brought on stream.

Christina Verchere, CEO of OMV Petrom: "With the final investment decision for the Neptun Deep project, we are opening a new game-changing chapter for the Romanian energy sector. Together with our partner, Romgaz, we are entering the development phase of the first deepwater offshore project in Romania. The project will contribute to Romania’s economic growth and will strengthen the country's energy security. To give an example of the project’s size: the estimated natural gas production is equivalent to ~30 times the current annual demand of ~4,300,000 households. It is also a major step forward for our Strategy 2030 that aims at supporting the energy transition in Romania and in the region".

Răzvan Popescu, General Manager of Romgaz: "Neptun Deep is a strategic project for Romania and for the region from the perspective of ensuring the natural gas needs and from the perspective of decarbonization. Starting with 2027, we will have a new source of natural gas, which has the potential to significantly increase the country's natural gas production. We are proud to be part of an innovative project, which will bring significant benefits to the country, in the long term".

Aristotel Jude, Deputy General Manager: “The Neptun Deep project enters today a new phase, the decision to invest in the development of the fields in this perimeter is a historic one for all interested parties and will bring undeniable benefits to Romania's energy security and independence. We remain committed to achieving the objectives of this project and we are confident that the National Agency for Mineral Resources will confirm, as soon as possible, the development plan for the Domino and Pelican South commercial fields in the Neptun Deep block, from which point the development stage of these fields will effectively start."

The infrastructure required for the development of the Domino and Pelican South offshore natural gas fields includes 10 wells, 3 subsea production systems and associated flow lines, an offshore platform, the main natural gas pipeline to Tuzla and a natural gas measurement station. The platform generates its own energy, operating at the highest standards of safety and environmental protection. The entire infrastructure will be operated remotely, through a digital twin. This allows for process optimization and will contribute to the improvement of environmental performance, by making energy consumption more efficient and reducing emissions.

First production is estimated for 2027. Production at the plateau will be approximately 8 bcm annually (~140,000 boe/d), for almost 10 years.

About Neptun Deep

The Neptun Deep Block in the Black Sea has an area of ​​7,500 square km and is located at about 160 km from the shore, in waters between 100 and 1,000 meters deep. Since 2008, the exploration activities in the Neptun Deep block have included two 3D seismic acquisition campaigns and two exploration drilling programs.

TechnipFMC Awarded Significant Contract by Woodside for Julimar Phase 3 Development

TechnipFMC (NYSE: FTI) has been awarded a significant(1) contract by Woodside Energy(2) (LON: WDS) to engineer, procure, construct, and install flexible pipes and umbilicals for the Julimar Phase 3 development, offshore Western Australia.

The Company will tie back four subsea gas wells in the Carnarvon Basin to the existing Julimar subsea infrastructure producing to the Wheatstone platform, using high pressure, high temperature (HPHT) flexible pipe and steel tube umbilicals.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “We have a strong history of solid project execution with Woodside as demonstrated by the successful delivery of the Pyxis, Lambert Deep, and Greater Western Flank Phase 3 projects. We look forward to continuing this collaborative relationship with this award on Julimar Phase 3 as part of our framework agreement.”

Baker Hughes Awarded Major Subsea Contract from Eni in Ivory Coast

Baker Hughes (NASDAQ: BKR), an energy technology company, has been awarded a major contract by Eni and its partner Petroci for the Baleine Phase 2 project in Ivory Coast, Africa’s first Scope 1 and 2 net-zero emissions development.

This award, which includes eight deep water trees, three Aptara™ manifolds, the relevant subsea production control system, and flexible risers and jumpers, strengthens Baker Hughes’ presence in West Africa and unlocks considerable growth potential in the country.

Baker Hughes will deliver a configured-to-order product portfolio across subsea production and flexible pipe systems, designed for optimum cost effectiveness, installation and life-of-field value. These deepwater trees and manifolds, supplemented with subsea production controls and flexible pipe systems, provide efficiency and cost-effectiveness under demanding conditions. Their modular design aids in reducing lead times, vital for the economic feasibility of such projects. This contract reflects Baker Hughes’ value proposition of advanced technology, exceptional execution and value, holistic solutions and operational efficiency.

“This collaboration between Baker Hughes and Eni is Africa’s first development project with clear Scope 1 and 2 carbon reduction goals and will deliver innovative technology that will enhance the energy security in Ivory Coast,” said Maria Claudia Borras, executive vice president, Oilfield Services & Equipment at Baker Hughes. “Ensuring that energy is locally available is an increasingly profound challenge, and we applaud the efforts of Eni and companies like it to shape an abundant energy future for Africa. We are proud of the confidence placed in us to accelerate the execution of this important project.”

Petrobras on the start-up of FPSO Almirante Barroso

Petrobras informs that it started today the production of the FPSO Almirante Barroso platform, in the Búzios field, with capacity to produce daily up to 150 thousand barrels of oil and 6 million m³ of gas. FPSO Almirante Barroso will contribute to the oil production of the Búzios field, which currently averages 560,000 barrels per day, equivalent to about 17% of national production.

"Búzios synthesizes how representative the pre-salt is for Petrobras' production, besides being important for the country's energy security. By 2025 we will have the entry of other units and the field's production should reach close to the 700,000 barrels per day mark”, declared Petrobras CEO, Jean Paul Prates.

FPSO Almirante Barroso is a unit chartered from Modec and is located 180 km off the coast of Rio de Janeiro, and operates its production in a water depth of 1,900 meters. It is the fifth platform to start operating in the Búzios field, where the P-74, P-75, P-76, and P-77 units were already in production.

Búzios is the largest deepwater field in the world and the current development concept includes 11 platforms. Currently, six units are under construction (FPSO Almirante Tamandaré, P-78, P-79, P-80, P-82, and P-83). Petrobras is the operator of the field, with 88.99% stakes in the shared Búzios field, with CNOOC holding 7.34% and CNODC 3.67% as partners.